1. Field of the Invention
This invention is related to measuring the dynamically changing pore fluid properties of the hydrocarbon reservoir due to injection and production at different time intervals. More specifically, the invention is related to using elastically nonlinear seismic imaging methods to identify the fluid fronts and the bypassed hydrocarbons. The fluid movements, fluid saturation changes, and the temperature variations in the reservoir due to injection and production processes are mapped. The periodic monitoring of the movement of fluids due to drainage and injection enables one to improve the overall production plan and reservoir management.
2. Description of the Related Art
Time-lapse seismic methods have been used during the last ten years, where two-dimensional (2-D) or three-dimensional (3-D) seismic data is recorded at different intervals of time to monitor the changes in seismic character and amplitude. The reservoir monitoring methods, which use surface land seismic, marine seismic or downhole seismic, try to image small changes in the reservoir seismic response from one survey to the next survey. These surveys are recorded at different time intervals.
The time-lapse seismic response quite often is non-unique, since the changes in reflection amplitude and its character can be caused due to various factors. The same seismic response can be caused due to changes in oil saturation, gas-to-oil ratio, pressure variation, temperature changes etc. Reservoir seismic response has many variables, and at present, there are not enough seismic attributes to solve them. To characterize reservoir properties with a higher level of confidence, more seismic attributes in addition to amplitude, attenuation and velocity are needed.
New seismic techniques, which are more sensitive to the changes in the reservoir conditions, have to be developed and introduced to enable one to better interpret the seismic results in terms of petrophysical properties of the reservoir rocks.
Time-lapse seismic, which is also known as 4-D, has a great deal of potential as a reservoir surveillance tool. 4-D can enable one to monitor the changes over time due to fluid movement during hydrocarbon production. It provides an analysis of the hydrocarbon sweep efficiency and can act as a guidline for better reservoir management through out the life of the reservoir. Nonlinear time-lapse seismic integrated with the current imaging technology will overcome the weaknesses that exist due to ambiguity of the results.
In many of the producing fields, unproduced hydrocarbons have been left behind because the industry lacks a technology that will identify the trapped and unproduced hydrocarbons due to the complex geology of the reservoirs. At present the hydrocarbon extraction technologies, in the form of horizontal and multilateral drilling and intelligent well completions, exist. What is lacking is a reliable subsurface imaging method with the required resolution to map the reservoir characteristics, the reservoir fluids and their movement. A seismic technology that will provide reliable information regarding the petrophysical properties of the reservoir rocks and its pore fluids is needed.
This invention provides a new method where measurements of the changes in the elastic nonlinearity of the saturated reservoir rocks are used to detect the changes in the reservoir fluids. Seismic signals transmitted from the surface or from the wellbore, and recorded at the surface, wellbore or both, are analyzed to determine the elastic nonlinearity of the reservoir rocks due to porosity, permeability, micro-fractures, and more specifically the pore fluids.
Heterogeneous materials, such as reservoir rocks, have extreme elastically nonlinear behavior due to their structural defects. Large deviations in their nonlinear and hysteretic properties can be caused when the consolidation and/or saturation conditions change in the reservoir. Accurate measurement of the changes in elastic nonlinear properties can be a sensitive measure of the pore fluids and their movement.
In the linear theory of elasticity two elastic waves do not interact, the equations of motion are linear, and the principle of superposition holds. In an elastically nonlinear medium, Westervelt (1963) was the first to show that two collinear high-frequency primary waves could interact to produce acoustic waves with frequencies equal to the sum and difference frequencies of the primaries. Additionally, when a discrete frequency seismic signal or a swept frequency seismic signal is used, there is an interaction with itself. Due to this interaction with itself, the related harmonics are generated as the signal propagates through an elastically nonlinear reservoir formation. The relative amplitudes of the odd and even harmonics that are generated depend on the physical properties of the rock and its pore fluids. Odd or even harmonics at the seismic frequencies may dominate the output spectra. The relative amplitudes of these odd and even harmonics will depend on the viscosity of the pore fluids. The measurement of the changes in the relative amplitudes of these odd and even harmonics caused due to hydrocarbon production over time can be used as a sensitive measure of the fluid changes in the reservoir rock.
Over a period of time, due to hydrocarbon production from a reservoir, there are changes in the pressure distribution, oil water contact, gas/oil ratio, temperature, etc. Seismic sensitivity to these changes that occur due to production and injection, can be used for nonlinear time-lapse seismic, to monitor the bypassed oil, map fluid flow barriers, fluid saturation changes, and for mapping the fluid fronts. The changes in the internal parameters of the reservoir rocks, due to fluid movement, affect the propagation characteristics of the seismic wave as it travels through the reservoir at different time intervals during a production or injection phase. Since the propagation of seismic wave is a coupled motion between rock matrix and pore fluids, its propagation characteristics change according to the changes of the internal parameters in the reservoir. The changes in the viscosity of the reservoir pore fluids make a major contribution in the elastically nonlinear seismic response of the time-lapse seismic recording.
Viscosity is the property of a fluid that tends to prevent it from flowing when subjected to an applied force; high viscosity fluids resist flow while low viscosity fluids flow easily. Because of this effect, the seismic wave propagation characteristics are different during the propagation of the seismic wave through the rocks that have high viscosity pore fluids versus low viscosity pore fluids. During the propagation of a seismic wave through a fluid saturated reservoir rock, viscosity determines the amount of friction and the energy absorbed, which in turn determines the amount of distortion and the type of harmonics generated.
When a seismic wave travels through a sedimentary reservoir rock, the matrix (mineral frame) of the rock is deformed; the pore fluid is compressed, dragged and pressured to flow. Fluids and solids are compressed as if they were individual springs connected together in different configurations. The pore fluids are mobile, so they are squeezed and squirted out of the thin cracks into larger pores as the rock matrix is compressed by the propagation of a seismic wave. The solid/fluid interaction is intimately connected. The viscosity of the pore fluid plays an important part in a solid""s oscillatory motion due to viscous friction and inertial coupling. The type of fluid and its viscosity in the pore space and at the grain contacts has a large influence on the rock stiffness. Due to elastic nonlinearity and the pore fluid viscosity, hysteresis is observed in the stress-strain relationship of a reservoir rock when exposed to an oscillatory seismic wave.
Hysteresis is a property of viscoelastic materials and is strongly associated with the pore fluid motion. Hysteresis represents the history dependence of physical systems. If you push on something, it yields: when you release, does it spring back completely? If it does not, it is exhibiting hysteresis. So, if there is a difference in the stress/strain relation between loading and unloading cycles of a rock than it can be categorized as hysteretic. The area of the stress/strain hysteresis loop represents energy dissipation as heat during the load cycle.
When a sinusoidal seismic wave propagates through the reservoir rock, the load is reversed from the compression to the rarefaction cycle of the seismic wave; the pore fluid is rearranged due to the deformation of the rock matrix in a confined space. This causes a lag between stress and strain, determining the size of the hysteresis loop. This phenomenon is dominated by the properties of the pore fluids. Time lag is fluid dependent; long chain fluid molecules give rise to higher time lags. Higher hysteresis at seismic frequencies is related to the higher viscosity of the pore fluids. Oil that has higher viscosity compared to water and gas will display a more pronounced hysteretic behavior to an oscillatory seismic wave, compared to water or natural gas that has lower viscosity. Since the nonlinear hysteretic behavior of the saturated reservoir rock generates harmonics of the primary signal, the measurement of these harmonics can be used as a diagnostic tool for determining the fluid saturation and the type of pore fluids.
The characteristic of the second and other even harmonics is that the primary signal waveform during compression and rarefaction cycles is not identical. So the presence of the even harmonics is indicative that the compression cycle of a sinusoidal seismic wave is different from the rarefaction cycle. The rock behaves differently when it is compressed compared to when the compression is removed.
The third harmonic, on the other hand, is generated when the distortion during compression and rarefaction cycles of the sinusoidal seismic wave is symmetrical. This indicates that the stress/strain relationship at seismic frequencies during compression and rarefaction cycles is similar. This in turn is indicative that the viscosity of the pore fluids is such that the rock is exhibiting less hysteresis. Pore fluids have lower viscosity. Note that these harmonics in consideration are not generated by the vibratory source, but are generated in the earth during the seismic signal propagation through the nonlinear rocks of the reservoir.
Due to the complex nature of the rock composition, we may expect both odd and even harmonics generated when a seismic wave travels through an elastically nonlinear reservoir rock. But, the amplitude of the even harmonics will be greater and dominate when the pore fluids have higher viscosity like oil. The amplitude of the odd harmonics will be more pronounced when we have lower viscosity pore fluids like natural gas. The measurements of the relative amplitudes of the odd and even harmonics of a primary seismic wave (signal) and the differences in their relative amplitudes over time will indicate the changes and the movement of the pore fluids caused due to hydrocarbon production.
When the seismic reflection data are recorded using a vibratory source that transmits a swept frequency signal, the cross-correlation with the transmitted signal provides a primary data set that is free from the harmonics generated by the nonlinearity of the earth. This represents the standard and conventional seismic reflection image being used today in the industry. However, when the same data-set is cross-correlated with different harmonics of the swept frequencies, the result of the cross-correlation is the reflected image of the subsurface which is illuminated with each particular harmonic. Harmonics of the primary swept frequency signal are generated only during the propagation of the primary signal through the reservoir, which is nonlinear due to its porosity and its pore fluids. For this reason, the reflected image created by each harmonic displays only the reservoir and its pore fluids. The formations, which consist of nonporous rocks and do not have any pore fluids, will not be visible and will appear as a non-coherent signal on the seismic reflection image.
The seismic reflection image generated by the result of cross-correlation with the second harmonic will represent the part of the reservoir that is porous and has higher viscosity pore fluids. In the same manner, the result of the cross-correlation with the third harmonic will illuminate the part of the reservoir that is saturated with the lower viscosity fluids.
This invention provides a method of mapping the reservoir fluids and monitoring their movement over a period of time due to production and injection. The measurements of the relative amplitudes of the reflected image of the reservoir mapped by the odd and even harmonics of the primary input signal are used to determine the changes of the reservoir fluids in the reservoir rocks due to hydrocarbon production over a period of time. The dominance of the even harmonics in the reflected seismic signals is indicative of the higher viscosity pore fluids like oil, and the dominance of the odd harmonics indicate presence of the lower viscosity fluids like natural gas. Any changes in the relative amplitudes of the odd or even harmonics, in time-lapse recording, will relate to the changes in the reservoir pore fluids that have taken place due to hydrocarbon production. By mapping and displaying the subsurface seismic reflection image of the reservoir generated by each of the odd and even harmonics and monitoring the changes in their relative amplitudes over time, the movement of the reservoir fluids can be mapped. The method described in this invention is equally applicable for surface seismic recording methods, borehole seismic or any combination of the wellbore and surface seismic.